Geophysical survey systems and related methods

ABSTRACT

Geophysical survey methods. At least some of the example embodiments are methods of performing a marine geophysical survey including: towing a plurality of sensor streamers behind a tow vessel, each sensor streamer coupled to the tow vessel by a respective lead-in cable; towing, by the tow vessel, a plurality of lead vessels with each lead vessel pulling a respective seismic source, each lead vessel pulled by a respective tow cable and at least one intermediate cable; actuating the respective seismic sources pulled by the plurality of lead vessels; and gathering seismic data by each of the sensor streamers.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. application Ser. No. 15/280,223filed Sep. 29, 2016 titled “Geophysical Survey Systems and RelatedMethods” (now U.S. Pat. No. 10,234,585), which claims the benefit ofU.S. Provisional Application Ser. No. 62/265,803 filed Dec. 10, 2015.Both applications are incorporated by reference herein as if reproducedin full below.

BACKGROUND

Geophysical surveying (e.g., seismic, electromagnetic) is a techniquewhere two- or three-dimensional “pictures” of the state of anunderground formation are taken. Geophysical surveying takes place notonly on land, but also in marine environments (e.g., oceans, largelakes). Marine geophysical surveying systems frequently use a pluralityof streamers which contain sensors to detect energy reflected fromunderground formations below the water bottom. Seismic streamers includesensors for detecting seismic signals reflected from undergroundformations below the water bottom, including formations containinghydrocarbon deposits.

In terms of area covered by a marine geophysical survey, better economicefficiency is achieved with wider streamer spreads that include a numberof sensor streamers. However, in shallow water (e.g., less than about300 meters) the economic efficiency is offset to some extent byincomplete data for shallow reflectors at the edges of the streamerspread.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of exemplary embodiments, reference will nowbe made to the accompanying drawings in which:

FIG. 1 shows a perspective view of a geophysical survey system;

FIG. 2 shows a perspective view of a geophysical survey system inaccordance with at least some embodiments;

FIG. 3 shows a side elevation view of a geophysical survey system inaccordance with at least some embodiments;

FIG. 4 shows a side elevation (partial cutaway) view of a lead vesseland seismic source in accordance with at least some embodiments;

FIG. 5 shows a side elevation (partial cutaway) view of a lead vesseland seismic source in accordance with at least some embodiments;

FIG. 6 shows an illustration of timing of activation of seismic sourcesin accordance with at least some embodiments;

FIG. 7 shows an illustration of timing of activation of seismic sourcesin accordance with at least some embodiments;

FIG. 8 shows an illustration of timing of activation of seismic sourcesin accordance with at least some embodiments;

FIG. 9 shows a perspective view of a geophysical survey system inaccordance with at least some embodiments;

FIG. 10 shows a perspective view of a geophysical survey system inaccordance with at least some embodiments;

FIG. 11 shows a perspective view of a geophysical survey system inaccordance with at least some embodiments; and

FIG. 12 shows a method in accordance with at least some embodiments.

The various views of the drawings are not necessarily to scale.

Definitions

Certain terms are used throughout the following description and claimsto refer to particular system components. As one skilled in the art willappreciate, different companies may refer to a component by differentnames. This document does not intend to distinguish between componentsthat differ in name but not function.

In the following discussion and in the claims, the terms “including” and“comprising” are used in an open-ended fashion, and thus should beinterpreted to mean “including, but not limited to . . . .” Also, theterm “couple” or “coupled” is intended to mean either an indirect ordirect connection. Thus, if a first device is coupled to a seconddevice, that connection may be through a direct connection or through anindirect connection via other devices and connections.

“Cable” shall mean a flexible, axial load carrying member that alsocomprises electrical conductors and/or optical conductors for carryingelectrical power and/or signals between components.

“Rope” shall mean a flexible, axial load carrying member that does notinclude electrical and/or optical conductors. Such a rope may be madefrom fiber, steel, other high strength material, chain, or combinationsof such materials.

“Line” shall mean either a rope or a cable.

“Proximal end” in reference to a sensor streamer shall mean an endnearest the tow vessel.

DETAILED DESCRIPTION

The following discussion is directed to various embodiments of theinvention. Although one or more of these embodiments may be preferred,the embodiments disclosed should not be interpreted, or otherwise used,as limiting the scope of the disclosure, including the claims. Inaddition, one skilled in the art will understand that the followingdescription has broad application, and the discussion of any embodimentis meant only to be exemplary of that embodiment, and not intended tointimate that the scope of the disclosure, including the claims, islimited to that embodiment.

Various embodiments are directed to marine geophysical survey systemsusing distributed seismic sources to reduce near source-receiver offsetissues. More particularly, in some example systems, the seismic sourcesare pulled by lead vessels coupled at the proximal end of some or allthe sensor streamers. That is, in some example embodiments the lead-incable that couples to a sensor streamer and provides a towing force forthe sensor streamer also provides a towing force that pulls the leadvessel and the seismic source coupled to the lead vessel. Having aseismic source at the proximal end of some or all the sensor streamersreduces the source-receiver offset. For example, the inline offset(i.e., the vector offset projected onto the sail line), and/or thecross-line offset (i.e., the vector offset projected onto a directionorthogonal to the sail line) are reduced with seismic sources at theproximal ends of some or all the sensor streamers. In other examplesystems, the lead vessels and related seismic sources are coupled at thedistal end of the sensor streamers. Related methods are directed tofiring sequences of the distributed sources, such as simultaneous firingof the seismic sources, sequential firing of the seismic sources, orrandom or quasi-random firing of the seismic sources. The specificationfirst turns to an example system to highlight near source-receiveroffset issues.

FIG. 1 shows a perspective view of an example geophysical survey system100. In particular, the geophysical survey system of FIG. 1 has a towvessel 102 towing a streamer spread 104. The example streamer spread 104comprises a plurality of sensor streamers 106, where each sensorstreamer has a plurality of receivers or sensors (not specificallyshown) spaced along the sensor streamer. The sensor streamers 106 areeach coupled, at the ends nearest the tow vessel 102, to respectivelead-in cable terminations 108. The lead-in cable terminations 108 arecoupled to or are associated with the spreader lines (not specificallynumbered) so as to control the lateral positions of the sensor streamers106 with respect to each other and with respect to the tow vessel 102.Towing force for the sensor streamers 106, as well as communicativeconnections between the components in the recording system on the towvessel and the sensors, is provided by the tow vessel 102 by way oflead-in cables 110. Each sensor streamer also has an associated leadbuoy 112 coupled to the proximal end of the respective sensor streamerby way of lines 114. The lead buoys 112 not only mark the proximal endof the sensor streamers, but in some cases also provide depth controlfor the proximal end of the sensor streamers 106. In most cases the leadbuoys 112 are relatively small (e.g., five or six meters) owing torelatively small amount of buoyancy needed to support the proximal endsof the sensor streamers 106.

The example system of FIG. 1 also comprises a seismic source 116. Theseismic source 116 is towed by dedicated tow cable 118 coupled betweenthe seismic source 116 and the tow vessel 102. The tow cable 118 thatpulls the seismic source 116 may include an umbilical with tubing toprovide compressed air to the seismic source (e.g., air at 2000 poundsper square inch gauge (psig)) in addition to electrical power andcommunicative pathways. The tow cable for the seismic source 116 issometimes referred to as “gun umbilical cable.” Because of the variouscomponents, the tow cable 118 for the seismic source 116 may havesignificantly greater diameter than, for example, lead-in cables 110,and thus towing force for the tow cable 116 is higher than for anequivalent length of lead-in cable 110.

The streamer spread 104 may include many sensor streamers 106, and inthe example system shown the streamer spread 104 includes 20 sensorstreamers 106 (and related lead-in cables 110 and lead buoys 112). Inmany cases the spacing S between adjacent sensor streamers 106 may bebetween 25 and 200 meters, usually about 100 meters (measuredperpendicular to the sail line of the tow vessel), and thus for theexample streamer spread 104 having 20 sensor streamers the overall widthW (again measured perpendicular to the sail line) may be about twokilometers.

While FIG. 1 shows the seismic source 116 as a single entity, in manycases the seismic source 116 is made of two or more separately towedsource arrays. Thus, each source array may have its own tow cabledirectly coupled the tow vessel, and each source array may have steeringcapability to separate the source arrays from each other. For sourcearrays towed directly by the tow vessel 102, the separation between thesource arrays may be about 50 meters. Nevertheless, the separationbetween the source arrays is relatively small in comparison to theseparation S between the sensor streamers 106 and the overall width W ofthe streamer spread 104. Because of the scale of the separation betweensource arrays compared to the scale of the separation S between thesensor streamers, for many cases where the seismic source 116 is towedbehind the tow vessel 102 the seismic source 116 resides between theinnermost sensor streamers, but the positioning of the seismic source116 is not so far back as to tangle with the lead buoys 112 and lines114 for the innermost sensor streamers 106.

The position of a seismic source 116 towed directly by the tow vessel102 in combination with streamer spreads having a large width W createsissues in geophysical surveys in shallow water and for relativelyshallow underground reflectors. In particular, and still referring toFIG. 1, the source-receiver offset between the seismic source 116 andreceivers (not specifically shown) on the innermost sensor streamers 106is relatively short (e.g., 100 to 300 meters); however, thesource-receiver offset between the seismic source 116 and the receiverson the outermost sensor streamers is significant. For the example systemof FIG. 1, with 100 meter separation S between the sensor streamers 106the source-receiver offset for the outermost sensor streamers may be onthe order of about 1 kilometer. However, for shallow undergroundreflectors in shallow water the largest usable near source-receiveroffset may be about 500 meters, and thus the outer sensor streamers maybe unusable. It follows that the recorded data may contain swaths ofunusable or missing data between the sail lines for shallow water andshallow underground reflectors.

The issues noted above are addressed, in large part, by a newgeophysical surveying systems (and related methods) that distribute theseismic sources to be associated with some or all the sensor streamers.FIG. 2 shows a perspective view of a geophysical survey system 200 inaccordance with example embodiments. In particular, FIG. 2 shows a towvessel 202 having onboard equipment 204, such as navigation, energysource control, and data recording equipment. Tow vessel 202 isconfigured to tow a plurality of sensor streamers 206 through the water,with the path of the tow vessel 202 referred to as a sail line 203.While FIG. 2 illustratively shows 20 sensor streamers 206, greater orfewer numbers of sensor streamers may be used.

The sensor streamers 206 are coupled to towing equipment that maintainsthe sensor streamers 206 at selected lateral positions with respect toeach other and with respect to the tow vessel 202. The towing equipmentmay comprise two paravane tow lines 208A and 208B each coupled to thetow vessel 202 by way of winches (not specifically shown). The winchesmay enable changing the deployed length of each paravane tow line 208Aand 208B. The second end of paravane tow line 208A is coupled to aparavane 210A, and the second end of paravane tow line 208B is coupledto paravane 210B (the paravanes sometimes referred to as “doors.”) Ineach case, the paravane tow lines 208A and 208B couple to theirrespective paravanes through respective sets of lines called a “bridle”(shown but not specifically numbered). The paravanes 210A and 210B areeach configured to provide a lateral force component to the variouselements of the survey system when the paravanes are towed through thewater. The combined lateral forces of the paravanes 210A and 210Bseparate the paravanes from each other until the paravanes put one ormore spreader lines 212, coupled between the paravanes 210A and 210B,into tension.

The sensor streamers 206 are each coupled, at the ends nearest the towvessel 202 to a respective lead-in cable termination 214. The lead-incable terminations 214 are coupled to or are associated with thespreader lines 212 so as to control the lateral positions of the sensorstreamers 206 with respect to each other and with respect to the towvessel 202. Electrical and/or optical connections between theappropriate components in the onboard equipment 204 and the sensors (notspecifically shown) in the sensor streamers 206 may be made using innerlead-in cables 216. Moreover, each lead-in cable 216 provides towingforce for its respective sensor streamer 206 as the tow vessel 202 towsthe streamer spread 218 during a geophysical survey. Much like the towlines 208A and 208B associated paravanes 210A and 210B, each of thelead-in cables 216 may be deployed by a respective winch or similarspooling device (not specifically shown) such that the deployed lengthof each lead-in cable 216 can be changed, such as during turns of thetow vessel 202.

The length of each sensor streamer 206 is fixed for a particulargeophysical survey, but the length of the sensor streamer may range fromas short as a few thousand meters, to lengths of 10,000 meters or morein other cases. In many cases, the spacing S between adjacent sensorstreamers 206 may be between and including 25 to 200 meters, in manycases about 100 meters (measured perpendicular to the sail line of thevessel), and thus for the example streamer spread 218 having 20 sensorstreamers 206 the overall width W (again measured perpendicularly to thesail line) may be about two kilometers.

In various embodiments discussed herein, each sensor streamer 206 maycomprise sensors in the form of a plurality of hydrophone-velocitysensor pairs spaced along the sensor streamer. That is, each sensor of asensor streamer 206 may comprise a hydrophone and co-located velocitysensor. A hydrophone is a device which creates an output signal (e.g.,electrical, optical) proportional to pressure sensed by the hydrophone,and more particularly to changes in pressure proximate the hydrophone asacoustic signals traveling in the water pass the hydrophone. A velocitysensor shall mean a device which senses particle motion, and produces anoutput signal (e.g., electrical, optical) responsive to small movements,velocity, and/or acceleration as acoustic signals travelling in thewater pass the sensor. Thus, the velocity sensor may likewise be anaccelerometer, and can be implemented in any suitable form, such aspiezoelectric accelerometers, micro electro-mechanical system (MEMS)accelerometers, and so on. In most cases the hydrophone and velocitysensor of a pair are within a few centimeters of each other (e.g., 10centimeters), but closer spacing and longer spacing is alsocontemplated. In some cases, the velocity sensor is responsive only tomovements/acceleration in the vertical direction (e.g., a z-componentsensor); however, in other cases the sensor may be sensitive to alldirections. In yet still other cases, the velocity sensors may beomitted and only hydrophones may be used. In some cases, a plurality ofhydrophones may be wired together in groups such that the group ofhydrophones represents one channel in the recording system.

The sensors of the sensor streamer detect seismic energy reflected fromunderground reflectors (such as interfaces between rock formationshaving different acoustic properties). Unlike the situation of FIG. 1where the seismic source 116 is towed directly by the tow vessel 102between the two innermost sensor streamers 106, in accordance withexample systems the seismic sources are distributed across the streamerspread 218. In the example system of FIG. 2, each sensor streamer has anassociated seismic source 220 pulled by a lead vessel 222 (otherarrangements are discussed below). In particular, each sensor streamer206 has associated therewith a lead vessel 222 floating at or nearsurface of the body of water. In the example system of FIG. 2 the leadvessel 222 is coupled to the proximal end of its associated sensorstreamer 206 by way of a tow cable 224 that extends between the proximalend of the sensor streamer 206 (in some cases the lead-in cabletermination 214) and the lead vessel 222. The seismic source 220 is inthe water behind the lead vessel 222, with the seismic source 220coupled to the lead vessel by a source cable 226 that extends from thelead vessel 222 to the seismic source 220.

Unlike the systems of FIG. 1 where the seismic source 116 is toweddirectly behind the tow vessel 102 by a tow cable 118 in the form of agun umbilical cable, in the example system of FIG. 2 each seismic source220 is pulled by a lead vessel 222. The lead vessel 222 is pulled by thetow cable 224 and the respective lead-in cable 216. Stated oppositely,the tow vessel 202 provides a towing force along the lead-in cable 216that pulls not only the sensor streamer 206, but also pulls the towcable 224, which pulls the lead vessel 222, which pulls the source cable226, which pulls the seismic source 220. It follows that while the towvessel 202 tows all the sources, the towing force is propagated along ahost of other components in the overall streamer spread 218.

Distributing the seismic sources 220 to be associated with some or allsensor streamers addresses the near source-receiver offset issue. Forthe example case of FIG. 2, with each sensor streamer 206 having anassociated seismic source 220, the near source-receiver offset for eachsensor streamer 206 is significantly shorter than situations where theseismic source is situated between the innermost sensor streamers of thestreamer spread (and closer to the tow vessel 202). Consider, forexample, the sensor streamer 206 on the far left side in the view ofFIG. 2. Since the sensor streamer 206 has an associated seismic source220 pulled by the lead vessel 222, the near source-receiver offset maybe only a few hundred meters or less depending on the location of thefirst sensor in the sensor streamer 206. In the example system of FIG.2, a near source-receiver offset for all the sensor streamers 206 isabout the same, and relatively short. By comparison, the nearsource-receiver offset in the system of FIG. 1 for the outermost sensorstreamers may be on the order of one kilometer. The near source-receiveroffset implemented in the example system of FIG. 2 means that even forsurveys in shallow water having relatively shallow undergroundreflectors, the data gathered may span substantially the entire width Wof the streamer spread.

FIG. 3 shows a side elevation view of the geophysical survey system 200of FIG. 2. In particular, visible in FIG. 3 are the tow vessel 202, asensor streamer 206, a lead vessel 222 associated with the sensorstreamer 206, and a seismic source 220 associated with the sensorstreamer 206 and the lead vessel 222. While only one sensor streamer 206and associated lead vessel and source are visible in FIG. 3 (e.g., theoutermost sensor streamer 206 on the right in FIG. 2), the descriptionthat follows is equally applicable to all the sensor streamers 206 andassociated equipment. As shown in FIG. 3, the tow vessel 202 couples tothe sensor streamer 206 and other equipment by the lead-in cable 216.The lead vessel 222 couples to the lead-in cable 216 by way of tow cable224. The seismic source 220 couples to the lead vessel 202 by way ofsource cable 226. In the example system of FIG. 3, the distal end 300 ofthe sensor streamer 206 couples to a tail buoy 302 which not only marksthe end of the sensor streamer 206 for navigation purposes, but the tailbuoy may also have GPS position location equipment such that the onboardequipment 204 (FIG. 2) in the tow vessel 202 can record with certaintythe location of the distal end of each sensor streamer 206.

The tow vessel 202 provides towing force for all the equipment shown,and the tow vessel tows the equipment along a direction of tow 304. Thatis, in the example system the tow vessel 202 tows everything shown byway of the lead-in cable 216. More particularly, the sensor streamer 206is pulled by the lead-in cable 216. The lead vessel 222 is pulled towcable 224, and tow cable 224 is pulled by lead-in cable 216. The seismicsource 220 is pulled by source cable 226 coupled to lead vessel 222, andagain lead vessel 222 is pulled tow cable 224 and tow cable 224 ispulled by lead-in cable 216. A few points before proceeding. First, asdiscussed with respect to FIG. 2, the spreader lines 212 (FIG. 2) andparavanes 210 (FIG. 2) provide a lateral force component for spacing theproximal ends of the various sensor streamers 206. While the majority ofthe towing force for the sensor streamer 206, lead vessel 222, andseismic source 220 are provided through the lead-in cable 216 in theexample system, depending on the angles and the state of the system(e.g., turning of the tow vessel 202), a small portion of the towingforce applied to the sensor streamer 206 and tow cable 224 may beprovided by the spreader lines 212 and paravanes 210 (FIG. 2). The smallportion of the towing force provided by the lateral spacing componentsshall not obviate that the various components are pulled by the lead-incable 216. Second, regardless of whether the entire towing force isalong the lead-in cable 216, or shared between the lead-in cable 216 andthe lateral spacing components, the towing force nevertheless originateswith the tow vessel 202.

FIG. 4 shows a side elevation, partial cutaway, view of the lead vessel222 and related components in accordance with example embodiments. Inparticular, FIG. 4 shows in greater detail the lead vessel 222 and anexample seismic source 220. The example lead vessel 222 takes the formof a small work boat. While the lead-vessel 222 may have a propulsionsystem (e.g., internal combustion engine coupled to a propeller disposedin the water), during a geophysical survey in accordance with exampleembodiments the propulsion system is not used, and instead the force tomove the lead vessel 222 and the seismic source 220 is provided from thetow vessel 202 (FIG. 2) by way of the tow cable 224. During deploymentand retrieval of the streamer spread 218, the propulsion system could beused. Nevertheless, each lead vessel may comprise a rudder 400 andrelated rudder positioning equipment 402 to provide lateral control andplacement of the lead vessel 222 (and thus the associated seismic source220) during geophysical surveys. Control of the lateral position may beby onboard equipment 204 of the tow vessel 202 (FIG. 2) communicatingrudder position commands along the communicative channels within thelead-in cable 216 (FIG. 2) and tow cable 224. In other cases, rudderposition commands may be communicated between the onboard equipment 204of the tow vessel 202 and the lead vessel 222 by way of wirelesscommunication, such as illustrated by antenna 404. In other cases, theonboard equipment 204 in the tow vessel 202 may provide a course to aposition control system 408 within the lead vessel 222, and the positioncontrol system 408 may: communicate with a GPS system to determiningposition (such as by determining position using GPS antenna 406); andimplement rudder position control based on a previously assigned course.The amount of lateral position control that may be implemented by thelead vessel 222 is bounded to some extent by length of the tow cable224, and in most cases it is contemplated that if position control isimplemented by the lead vessel 222, the position control will likely beto ensure the path of travel of the lead vessel 222 and seismic source220 is directly over the underlying sensor streamer (not shown in FIG.4). In yet still further cases, the towing of the lead vessel may bepassive in the sense the rudder of the lead vessel is not controlledduring towing.

In example systems, each lead vessel 222 has a non-planing displacementhull, in most cases a V-bottom type hull, but other hull types for thelead vessel are possible (e.g., round-bottom, flat-bottom, catamaran).The hull type need not be consistent across all the lead vessels in anoverall streamer spread. In example systems, each lead vessel 222 has alength L of between and including 10 and 20 meters (by contrast, thelead buoys 112 in the system of FIG. 1 may be less than 10 meters long,and in most cases five to six meters long). The length of the leadvessel 222 thus enables placement of certain equipment within the leadvessel 222 which further enables distribution of the seismic sources, asdiscussed immediately below.

Still referring to FIG. 4, the example lead vessel 222 comprises asource of energy 410 operatively coupled to the seismic source 220 byway of the source cable 226. In one example case, and as shown in FIG.4, the source of energy 410 is an air compressor 412 disposed within thelead vessel 222. In some cases, the air compressor 412 is turned by aninternal combustion engine 413 also disposed within the lead vessel.Compressed air from the air compressor 412 is operatively coupled to theseismic source 220 by way of the source cable 226. It follows that inthe example system the seismic source 220 is a source that usescompressed air to create the seismic energy. In the example shown inFIG. 4, the seismic source 220 is a source array 414. More particularly,the source array 414 comprises a buoy 416 coupled to an upper framemember 418, such as by straps 420. Suspended below the upper framemember 418 is a lower frame member 422, and suspended below the lowerframe member 422 are a plurality of air guns 424. While only four airguns are shown, in some cases the source array 414 may have between andincluding two and ten air guns. It follows from the physical connectionsthat the plurality of air guns 424 are suspended beneath the surface 426of the body of water. The depth of the lower frame member 422 (and thusthe air guns 424) may be controlled by cables that couple the upper andlower frame members. Compressed air and control signals for theplurality of air guns 424 may be provided along the source cable 226,and then through umbilical 430. Thus, seismic energy is selectivelycreated based on the delivery of compressed air (and control signals) tothe air guns 424. While FIG. 4 shows a single source array 414, in othercases multiple source arrays may be pulled behind each lead vessel, withthe number of source arrays selected to achieve the desired energyoutput.

As mentioned previously umbilical cables that include hoses fortransferring compressed air have greater diameters than sensorstreamers. By having an air compressor 412 in each respective leadvessel 222, and given the low towing force used for the lead vessels 222and relatively short source cables 226, the seismic sources 220 may beplaced at significantly greater distances from the tow vessel 202compared to, for example, attempting to supply compressed air from thetow vessel 202 to the most distance sensor streamers (a kilometer ormore in the example system of FIG. 2).

FIG. 5 shows a side elevation, partial cutaway, view of a lead vessel222 and related components in accordance with other example embodiments.In particular, FIG. 5 shows an example lead vessel 222 and an exampleseismic source 220. As with the system of FIG. 4, the example leadvessel 222 of FIG. 5 takes the form of a small work boat. Thedescription of FIG. 4 regarding the lead vessel 222, its propulsionsystem, the boat type, boat length, and the control of lateral positionis equally applicable to the system of FIG. 5, and will not be repeatedso as not to unduly lengthen the specification

The example lead vessel 222 of FIG. 5 also comprises a source of energy410 operatively coupled to the seismic source 220 by way of the sourcecable 226. However, in the case of FIG. 5 the source of energy 410 is anelectrical generator 500 disposed within the lead vessel 222. In somecases, the electrical generator is turned by an internal combustionengine 502 also disposed within the lead vessel. Electrical energy fromthe electrical generator 500 is operatively coupled to the seismicsource 220 by way of the source cable 226. It follows that in theexample system the seismic source 220 is a source that uses electricalenergy to create the seismic energy. In the example shown in FIG. 5, theseismic source 220 is a marine vibrator 504. More particularly, themarine vibrator 504 is suspended beneath a buoy 506 coupled to an upperframe member 508, such as by straps 510. The depth of the marinevibrator 504 may be controlled by cables that couple the marine vibrator504 to the upper frame member 508. Electrical energy for the marinevibrator is provided along the source cable 226. Thus, seismic energy isselectively created based on the delivery of the electrical energy tothe marine vibrator 504.

Still referring to FIG. 5, in yet still other cases, and depending onthe amount of electrical energy used by the marine vibrator 504, theelectrical energy may be supplied from the tow vessel 202 (FIG. 2) alongthe lead-in cable 216, then along tow cable 224, then along source cable226 to the marine vibrator 504. Thus, in such embodiments the electricalgenerator 500 may be omitted, yet the lead-vessel 222 still used asshown in FIG. 5. In some systems, each lead vessel and seismic sourcewill be of the same type. However, in other cases the seismic sourceassociated with each lead vessel need not be the same, and thus theoverall streamer spread may contain seismic sources in the form of airguns and marine vibrators.

The specification now turns to operational aspects of example systems.In particular, and as discussed above, in the example systems the towvessel 202 provides the towing force for the streamer spread 218, aswell as the lead vessels 222 and associated seismic sources 220. Thus,the tow vessel 202 tows the streamer spread 218 and related equipmentalong the sail line while the seismic sources 220 are activated.Activating the plurality of seismic sources 220 may take many forms. Inone example operational method, the seismic sources 220 are activatedsimultaneously. FIG. 6 shows an overhead view depicting location of eachseismic source at the time of activation for system having an exampleten seismic sources, and with those seismic sources being activatedsimultaneously. In particular, consider that a tow vessel (not shown) istravelling from left to right on the plane of the page of FIG. 6 towinga streamer spread with the seismic sources spread about the streamerspread. A first column of dots 600 depicts a location of the seismicsources for a first simultaneous activation of all the sources. That is,each dot in the column of dots represents a location of a single seismicsource when the seismic source is activated. Thus, all the sources areactivated simultaneously. At some later time (e.g., 10 seconds to a fewminutes depending on the depth of underground reflectors of interest)the sources are simultaneously activated again, and because of movementof the tow vessel the location of the seismic sources is changed fromthe first activation. Thus, FIG. 6 shows a second column of dots 602that depicts location of the seismic sources for a second simultaneousactivation of the sources. Columns of dots 604 and 606 likewise depictlocations of the seismic sources at a respective third and fourthsimultaneous activation of the seismic sources. “Simultaneous”activation in reference to FIG. 6 (and cases below where two or moresources are activated “simultaneously”) shall also include ditheredactivation. That is, “simultaneous” activation shall also includesituations where a plurality of source arrays are activated within atime window, with the amount of delay between the activations within thetime window precisely controlled yet the activations still considered“simultaneous.”

Simultaneously activating the seismic sources may be useful in certainsituations; however, for a large number of seismic sources the differingpath lengths to each underground reflector may create difficultiesduring processing of the seismic data. Thus, in yet still furtherexample operational methods, the seismic sources may be activatedsequentially. FIG. 7 shows an overhead view depicting location ofseismic sources at the time of activation for system having an exampleten seismic sources being activated sequentially. In particular,consider that a tow vessel (not shown) is travelling from left to righton the plane of the page of FIG. 7 towing a streamer spread with theseismic sources spread about the streamer spread. A first seismic sourceis activated (as shown by dot 700) as the streamer spread continues totravel through the water, and after a predetermined period of time(e.g., a few seconds to a few minutes) an adjacent seismic source isactivated (as shown by dot 702), and so on along all the seismicsources. The sequential firing results in a diagonal series of dots 704depicting the location of each seismic source at activation for thesequential activation. In the example methods, as soon as the lastseismic source is activated (as shown by dot 706), the sequentialactivation begins anew, as illustrated by the second diagonal series ofdots 708, and the third diagonal series of dots 710.

Sequentially activating the seismic sources may be useful in certainsituations; however, for a large number of seismic sources, anddepending on the depth of the underground reflectors of interest, thetime between activations of a particular seismic source may be too longto achieve suitable data coverage in the vicinity of the seismic source.Consider, as an example, a seismic source activation represented by dot700 and activation of the same seismic source after activation of allthe other seismic sources as represented by dot 712. If too much timeelapses between these activations of the seismic source, the reflectionsof seismic energy from underground reflectors beneath the path of travelof the seismic source may be too sparse to adequately image theunderground reflectors. The example of FIG. 7 has only ten seismicsources. The issues regarding the period of time between activations ofparticular sources (and sources near the particular sources) isexacerbated when additional seismic sources are present and/or withincreasing the depth of the underground reflectors of interest.

FIG. 8 shows an overhead view depicting locations of seismic sources atthe times of their activations in a system having an example ten seismicsources being activated in a either a random or a quasi-random manner.“Random” in this context refers to a sequence wherein each value isindependent of the prior values—that is, the values in the sequence arestatistically uncorrelated, to the extent computers are capable ofproducing such sequences. “Quasi-random” in this context refers to asequence having the appearance of randomness (i.e., the values exhibitno discernable pattern), but possibly having some statisticaldistribution imposed thereon such that the values in the sequence may bemore uniformly distributed than uncorrelated “random” values, so as toreduce the occurrences of clumps of similar values. Consider that a towvessel (not shown) is travelling from left to right on the plane of thepage of FIG. 8 towing a streamer spread with the seismic sources spreadabout the streamer spread. In the random or quasi-random firing, acomputer system may generate a random or quasi-random number selectedfrom a set consisting of the number of seismic sources in the streamerspread, and activates the selected seismic source. In the example shownin FIG. 8, if the source at the top of the figure is seismic source one,and the source at the bottom of the figure is seismic source ten, thefirst activation in the example shown is of seismic source nine, asillustrated by dot 800. The second activation in the example is ofseismic source three, as illustrated by dot 802. The third activation inthe example is of seismic source four, as illustrated by dot 804, and soon. Random or quasi-random activation have certain advantages in laterdata processing, such as data processing using the method known ascompressive (or compressed) sensing.

Any of the activation schemes shown FIGS. 6-8 could be dense or sparse.Sparse activation shall mean situations where the inline distance (i.e.,the distance survey vessel moves along the sail line 203) betweenactivation of seismic source(s) of the survey is more than about 20meters. That is, the distance the tow vessel travels along the sailbetween a first activation of seismic source(s) and an immediatelysubsequent activation of seismic source(s) is more than 20 meters. Bycontrast, a dense activation shall mean situations where the inlinedistance (i.e., the distance survey vessel moves along the sail line203) between activation of seismic source(s) of the survey is less than20 meters, and in some cases between 10 and 15 meters. That is, thedistance the tow vessel travels along the sail between a firstactivation and an immediately subsequent activation of seismic source(s)is between and including 10 and 15 meters. So for example, and referringto FIG. 8, if the survey vessel travels 20 meters or more (in the Xdirection of FIG. 8) between activation of seismic source illustrated bydot 802 and the activation illustrated by dot 804, and the remainingactivations have similar spacing, such would be considered sparseactivation. By contrast, if the survey vessel travels 12.5 meters (inthe X direction of FIG. 8) between activation of seismic sourceillustrated by dot 802 and the activation illustrated by dot 804, andthe remaining activations have similar spacing, such would be considereddense activation.

As shown in FIG. 8, the random or quasi-random activation is a sparseactivation, which in this case means that only one seismic source isactivated in each activation period. In yet still other cases, therandom or quasi-random activation may be dense, meaning that within eachactivation period multiple seismic sources (e.g., three, four) may beactivated.

The descriptions of the activation methods with respect to FIGS. 7 and 8assume only a single seismic source is fired at any one time; however,in yet still further embodiments multiple seismic sources (but less thanall the seismic sources) may be activated in the example patterns ofFIGS. 7 and 8. For example, source 700 may represent two or threeadjacent seismic sources fired simultaneously, and yet the “sequential”pattern of firing may be applied across the groups of adjacent seismicsources. Likewise, the random or quasi-random activation illustrated byFIG. 8 may be implemented by simultaneous activation of a predeterminednumber of the plurality of sources, where the seismic sourcesconstituting the predetermined number of sources are randomly orquasi-randomly selected. For example, at a first location three seismicsources may be simultaneously activated, and the three seismic sourcesare randomly or quasi-randomly selected from the group consisting of allthe seismic sources. At a subsequent location another three seismicsources may be simultaneously activated, and again the three seismicsources are randomly or quasi-randomly selected from the groupconsisting of all the seismic sources.

The specification now turns to further example systems in accordancewith various embodiments. In particular, FIG. 9 shows a geophysicalsurvey system 900 in accordance with example embodiments. In particular,FIG. 9 shows tow vessel 202 such as described with respect to FIG. 2.Tow vessel 202 is configured to tow a plurality of sensor streamers 206through the water. Much like the system of FIG. 2, the sensor streamers206 are coupled to towing equipment that maintains the sensor streamers206 at selected lateral positions with respect to each other and withrespect to the tow vessel 202. Moreover, the sensor streamers 206 areeach coupled, at the ends nearest the tow vessel 202 (i.e., the“proximal ends”) to a respective lead-in cable termination 214. Thelead-in cable terminations 214 are coupled to or are associated with thespreader lines (not specifically number) so as to control the lateralpositions of the sensor streamers 206 with respect to each other andwith respect to the tow vessel 202. Electrical and/or opticalconnections between the appropriate components in the onboard equipmentand the sensors (not specifically shown) in the sensor streamers 206 maybe made using inner lead-in cables 216. Moreover, each lead-in cable 216provides towing force for its respective sensor streamer 206 as the towvessel 202 tows the streamer spread 902 during a geophysical survey.

In the example system shown, some but not all the sensor streamers 206have associated therewith a lead vessel 222 floating at or near surfaceof the body of water. Where lead vessels are used, the lead vessel 222is coupled to the proximal end of its associated sensor streamer 206 byway of a tow cable 224 that extends between the proximal end of thesensor streamer 206 (in some cases the lead-in cable termination 214)and the lead vessel 222. A seismic source 220 is in the water behind itsrespective lead vessel 222, with the seismic source 220 coupled to thelead vessel by a source cable 226 that extends from the lead vessel 222to the seismic source 220. The lead vessels 222 and seismic sources maybe as discussed above in form and function, and thus completedescriptions of the lead vessels 222 and seismic sources will not berepeated again here so as not to unduly lengthen the specification. Theremaining sensor streamers 206 that do not have an associated leadvessel 222 and seismic source may be associated with a lead buoy 904.

In the example system shown, the number of lead vessels 222 (and thusthe number seismic sources 220) is less than the total number of sensorstreamers 206. The example system of FIG. 9 shows twenty sensorstreamers 206 and six lead-vessels 222 and respective seismic sources220, but greater or fewer lead-vessels and seismic sources, and likewisegreater or fewer sensor streamers 206, may be equivalently used (e.g., alead vessel and source associated with every-other sensor streamer).Moreover, FIG. 9 shows a seismic source 220 associated with each of theouter sensor streamers 206; however, the seismic sources 220 may beassociated with sensor streamers closer to the center of the streamerspread 902, and yet still address the issues associated with the largesource-receiver offsets experienced by systems where the seismic sourcesare situated between the inner-most sensor streamers.

FIG. 10 shows a geophysical survey system 1000 in accordance with yetstill further embodiments. In particular, FIG. 10 shows the sensorstreamers 206 towed behind the tow vessel 202 in the manner describedabove. FIG. 10 also shows lead vessels 222 and seismic sources 220associated with the sensor streamers; however, rather than being coupledat the proximal end of the sensor streamers, the example lead-vessels222 and seismic sources 220 are coupled at the distal ends of theirassociated sensor streamers 206. More particularly, each lead vessel 222in the system of FIG. 10 has a tow cable 224 that couples between thelead vessel 222 and the distal end of the associated sensor streamer206. Nevertheless, the towing force for the system shown in FIG. 10 isprovided in whole or in large part from the tow vessel 202. That is,towing force for the seismic sources 220 is provided to the lead-incables 216, along the sensor streamers 206, along the tow cables 224 tothe lead vessels 222, and then along the source cables 226 to theseismic sources 220.

The operational aspects of activating the various sources 220 of FIG. 10are the same as discussed above with respect to FIGS. 6-8, and will notbe repeated again here so as not to unduly lengthen the specification.Moreover, while FIG. 10 shows a lead vessel 222 and seismic source 220associated with every sensor streamer 206 in the example systems, havinglead-vessels 222 and seismic sources 220 associated with less than allthe sensor streamers 206 (similar to FIG. 9 except the association atthe distal end rather than the proximal end of each sensor streamer) isalso contemplated.

FIG. 11 shows a geophysical survey system 1100 in accordance with yetstill further embodiments. In particular, FIG. 11 shows the sensorstreamers 206 towed behind the tow vessel 202 in the manner describedabove. FIG. 11 also shows lead vessels 222 and seismic sources 220associated with sensor streamers in the manner similar to FIG. 9, wherethe number of seismic sources 220 and lead vessels 222 is less than thenumber of sensor streamers 206. The lead vessels 222 are coupled to theproximal end of the sensor streamers; however, tow cables 224 of FIG. 11are significantly longer than the tow cables previously discussed, andthe coupling to the proximal ends of the sensor streamers also includesa lead buoy 1102 and intermediate tow cable 1104. In particular, inaccordance with example embodiments of FIG. 11, the intermediate towcables 1104 may have a length about the same as the planned tow depthfor the sensor streamers 206, and the tow cables 224 may have a lengthon the order of half overall length the sensor streamers 206 such thatthe seismic sources 220 reside at about the middle of the respectivesensor streamer 206 over which each seismic source 220 is positioned.Thus, each tow cable 224 may be at least 25% of the length of anassociated sensor streamer 206, and in some cases each tow cable will beabout 50% of the length of an associated sensor streamer 206. Bycontrast, in the example systems of FIGS. 2 and 9 the seismic sources220 may reside proximal to the first sensor of each sensor streamer(e.g., over the stretch sections and/or one or more sections with noactive sensors). More particularly, each lead vessel 222 in the systemof FIG. 11 has a tow cable 224 that couples between the lead vessel 222and the lead buoy 1102, and the lead buoy 1102 has an intermediate towcable 1104 that couples between the lead buoy 1102 and the proximal endof the sensor streamer 206. As before, the towing force for the systemshown in FIG. 11 is provided in whole or in large part from the towvessel 202. That is, towing force for the seismic sources 220 isprovided to the lead-in cables 216, along the intermediate tow cable1104, along the tow cables 224 to the lead vessels 222, and then alongthe source cables 226 to the seismic sources 220. With longer tow cables224, the lead vessels 222 are more likely to implement active steering.

The operational aspects of activating the various sources 220 of FIG. 11are the same as discussed above with respect to FIGS. 6-8, and will notbe repeated again here so as not to unduly lengthen the specification.Moreover, while FIG. 11 shows a lead vessel 222 and seismic source 220associated with less than all the sensor streamer 206, havinglead-vessels 222 and seismic sources 220 associated with all the sensorstreamers 206 (similar to FIG. 2 except with longer tow cables 224) isalso contemplated. Having the seismic sources 220 positioned near themid-point of each sensor streamer enables “reverse push” surveying forthose sensors of the sensor streamers more proximal than the sources

FIG. 12 shows a method in accordance with at least some embodiments. Inparticular, the method starts (block 1200) and proceeds to towing aplurality of sensor streamers behind a tow vessel, each sensor streamercoupled to the tow vessel by a respective lead-in cable (block 1202).The method further comprises towing, by the tow vessel, a plurality oflead vessels with each lead vessel pulling a respective seismic source,each lead vessel pulled by a respective tow cable and at least oneintermediate cable (block 1204). As discussed above, in some cases theintermediate cable is the lead-in cable for the associated sensorstreamer. In other cases, the intermediate cable may be not only thelead-in cable, but also the sensor streamer itself when the lead-vesseland associated seismic source are disposed at the distal end of theassociated sensor streamers. The method may further comprise actuatingthe respective seismic sources pulled by the plurality of lead vessels(block 1206), and gathering seismic data by each of the sensor streamers(block 1208). Thereafter, the method ends (block 1210), in most cases tocontinue as the tow vessel tows the streamer spread along a sail line.

In accordance with a number of embodiments of the present disclosure, ageophysical data product may be produced. The geophysical data productmay include, for example, data collected in situations where the seismicsources are spread out across the proximal or distal end of the sensorstreamers as discussed in this specification. Geophysical data, such asdata previously collected by sensors, may be obtained (e.g., retrievedfrom a data library) and may be stored on a non-transitory, tangiblecomputer-readable medium. The geophysical data product may also beproduced by processing the gathered geophysical data offshore (i.e., byequipment on a vessel) or onshore (i.e., at a facility on land).

The above discussion is meant to be illustrative of the principles andvarious embodiments of the present invention. Numerous variations andmodifications will become apparent to those skilled in the art once theabove disclosure is fully appreciated. For example, the marine vibratorsdiscussed herein may be electrical marine vibrators, electro-mechanicalmarine vibrators, electro-hydraulic marine vibrators, and/or any othervibrator source emitting transient acoustic energy. It is intended thatthe following claims be interpreted to embrace all such variations andmodifications.

What is claimed is:
 1. A method of performing a marine geophysicalsurvey comprising: towing a plurality of sensor streamers behind a towvessel, each sensor streamer coupled to the tow vessel by a respectivelead-in cable; towing, by the tow vessel, a plurality of lead vesselswith each lead vessel pulling a respective seismic source, each leadvessel pulled by a respective tow cable and a respective lead-in cablethat is also pulling a sensor streamer; actuating the respective seismicsources pulled by the plurality of lead vessels; and gathering seismicdata by each of the sensor streamers.
 2. The method of claim 1 whereintowing the plurality of lead vessels further comprises towing theplurality of lead vessels with each lead vessel pulled by a respectivesensor streamer.
 3. The method of claim 1 wherein actuating therespective seismic sources further comprises simultaneously actuating.4. The method of claim 1 wherein actuating the respective seismicsources further comprises sequentially actuating in at least oneselected from the group consisting of: sparse actuation; and denseactuation.
 5. The method of claim 1 wherein actuating the respectiveseismic sources further comprises actuating in a quasi-random pattern.6. The method of claim 1 wherein actuating the respective seismicsources further comprises actuating in a random pattern.
 7. The methodof claim 1 wherein towing the plurality of lead vessels furthercomprises towing a number of lead vessels such that each sensor streamerhas an associated lead vessel.
 8. The method of claim 1 wherein towingthe plurality of lead vessels further comprises towing a number of leadvessels such that every-other sensor streamer has an associated leadvessel.
 9. A method of performing a marine geophysical surveycomprising: towing a plurality of sensor streamers behind a tow vessel,each sensor streamer coupled to the tow vessel by a respective lead-incable; towing, by the tow vessel, a plurality of lead vessels with eachlead vessel pulling a respective seismic source, each lead vessel pulledby a respective tow cable and at least one intermediate cable; actuatingthe respective seismic sources pulled by the plurality of lead vessels;gathering seismic data by each of the sensor streamers; operating arespective air compressor in each of the plurality of lead vessels, eachair compressor creating compressed air; and providing compressed air tothe respective seismic source pulled by the respective plurality of leadvessels; and creating seismic energy by each seismic source being one ormore air guns.
 10. A method of performing a marine geophysical surveycomprising: towing a plurality of sensor streamers behind a tow vessel,each sensor streamer coupled to the tow vessel by a respective lead-incable; towing, by the tow vessel, a plurality of lead vessels with eachlead vessel pulling a respective seismic source, each lead vessel pulledby a respective tow cable and at least one intermediate cable; actuatingthe respective seismic sources pulled by the plurality of lead vessels;gathering seismic data by each of the sensor streamers; operating arespective electrical generator in each of the plurality of leadvessels, each electrical generator creating electrical voltage andcurrent; providing electrical voltage and current to the respectiveseismic source pulled by the respective plurality of lead vessels; andcreating seismic energy by each seismic source being a marine vibrator.11. A method of manufacturing a geophysical data product, the methodcomprising: obtaining geophysical data by a sensor streamer spread wherea first seismic source is pulled behind a first lead vessel, the firstlead vessel is pulled by a tow cable coupled to a proximal end of afirst sensor streamer, and both the first lead vessel and the firstsensor streamer are pulled by a first lead-in cable coupled between theproximal end of the first sensor streamer and a tow vessel; andrecording the geophysical data on a tangible computer-readable medium.12. The method of claim 11 wherein the geophysical data is obtained bythe sensor streamer spread further comprising a second seismic sourcepulled behind a second lead vessel coupled to a proximal end of a secondsensor streamer of the sensor streamer spread, the second lead vesselcoupled to the second sensor streamer by a tow cable that extendsbetween the proximal end of the second sensor streamer and the secondlead vessel.
 13. The method of claim 12 wherein the first sensorstreamer and first lead vessel are a first outermost position of thesensor streamer spread, and the second sensor streamer and second leadvessel are a second outermost position of the sensor streamer spread,the second outermost position opposite the first outermost position. 14.The method of claim 12 wherein obtaining the geophysical data productfurther comprises actuating the seismic sources in a pattern being atleast one selected from the group consisting of: simultaneouslyactuating; sequentially actuating; actuating in a quasi-random pattern;and actuating in a random pattern.
 15. The method of claim 12 whereinobtaining the geophysical data product further comprises actuating theseismic sources in random pattern.